Absorbent for the selective removal of hydrogen sulfide

ABSTRACT

An absorbent for selective removal of hydrogen sulfide from a fluid stream comprises an aqueous solution comprising a) a tertiary amine; b) an aminic pH promoter selected from the compounds mentioned in the description; where the molar ratio of b) to a) is in the range from 0.05 to 1.0; and c) an acid having a pKA of less than 6 in such an amount that the pH of the aqueous solution measured at 120° C. is 7.9 to less than 8.8. Also described is a process for removing acidic gases from a fluid stream, in which the fluid stream is contacted with the absorbent. The absorbent is notable for a low regeneration energy.

The present invention relates to an absorbent for removing acidic gases from fluid streams, especially for selective removal of hydrogen sulfide, and to a process for removing acidic gases from a fluid stream, especially for selective removal of hydrogen sulfide over carbon dioxide.

The removal of acid gases, for example CO₂, H₂S, SO₂, CS₂, HCN, COS or mercaptans, from fluid streams such as natural gas, refinery gas or synthesis gas is important for various reasons. The content of sulfur compounds in natural gas has to be reduced directly at the natural gas source through suitable treatment measures, since the sulfur compounds form acids having corrosive action in the water frequently entrained by the natural gas. For the transport of the natural gas in a pipeline or further processing in a natural gas liquefaction plant (LNG=liquefied natural gas), given limits for the sulfur-containing impurities therefore have to be observed. In addition, numerous sulfur compounds are malodorous and toxic even at low concentrations.

Carbon dioxide has to be removed from natural gas among other substances, because a high concentration of CO₂ in the case of use as pipeline gas or sales gas reduces the calorific value of the gas. Moreover, CO₂ in conjunction with moisture, which is frequently entrained in the fluid streams, can lead to corrosion in pipes and valves. Too low a concentration of CO₂, in contrast, is likewise undesirable since the calorific value of the gas can be too high as a result. Typically, the CO₂ concentrations for pipeline gas or sales gas are between 1.5% and 3.5% by volume.

Acid gases are removed by using scrubbing operations with aqueous solutions of inorganic or organic bases. When acid gases are dissolved in the absorbent, ions form with the bases. The absorption medium can be regenerated by decompression to a lower pressure and/or by stripping, in which case the ionic species react in reverse to form acid gases and/or are stripped out by means of steam. After the regeneration process, the absorbent can be reused.

A process in which all acidic gases, especially CO₂ and H₂S, are very substantially removed is referred to as “total absorption”. In particular cases, in contrast, it may be desirable to preferentially absorb H₂S over CO₂, for example in order to obtain a calorific value-optimized CO₂/H₂S ratio for a downstream Claus plant. In this case, reference is made to “selective scrubbing”. An unfavorable CO₂/H₂S ratio can impair the performance and efficiency of the Claus plant through formation of COS/CS₂ and coking of the Claus catalyst or through too low a calorific value.

Highly sterically hindered secondary amines, such as 2-(2-tertbutylaminoethoxy)ethanol, and tertiary amines, such as methyldiethanolamine (MDEA), exhibit kinetic selectivity for H₂S over CO₂. These amines do not react directly with CO₂; instead, CO₂ is reacted in a slow reaction with the amine and with water to give bicarbonate—in contrast, H₂S reacts immediately in aqueous amine solutions. Such amines are therefore especially suitable for selective removal of H₂S from gas mixtures comprising CO₂ and H₂S.

The selective removal of hydrogen sulfide is frequently employed in the case of fluid streams having low partial acid gas pressures, for example in tail gas, or in the case of acid gas enrichment (AGE), for example for enrichment of H₂S prior to the Claus process.

For instance, U.S. Pat. No. 4,471,138 showed that highly sterically hindered secondary amines such as 2-(2-tert-butylaminoethoxy)ethanol, even in combination with further amines such as methyldiethanolamine, have a much higher H₂S selectivity than methyldiethanolamine. This effect was confirmed, inter alia, by Lu et al. in Separation and Purification Technology, 2006, 52, 209-217. EP 0 084 943 discloses the use of highly sterically hindered secondary and tertiary, alkanolamines in absorption solutions for selective removal of hydrogen sulfide over carbon dioxide from gas streams.

EP 134 948 describes an absorbent comprising an alkaline material and an acid having a pK_(A) of 6 or less. Preferred acids are phosphoric acid, formic acid or hydrochloric acid. The addition of acid is especially said to make the stripping of H₂S-comprising acidic gases more efficient.

U.S. Pat. No. 4,618,481 discloses the removal of hydrogen sulfide from fluid streams with an absorption solution comprising a highly sterically hindered amine and an amine salt. U.S. Pat. No. 4,892,674 discloses the removal of hydrogen sulfide from fluid streams with an absorption solution comprising an amine and a highly sterically hindered amino salt and/or a sterically hindered amino acid. One teaching of the document, with reference to FIG. 3, is that the H₂S selectivity of MDEA can be increased by addition of 2-(2-tertbutylaminoethoxy)ethanol sulfate.

Mandal et al. (In Separation and Purification Technology, 2004, 35, 191-202) describe selective H₂S removal from nitrogen-containing fluids using absorbents comprising 2-amino-2-methylpropanol (2-AMP) or MDEA. It was found that MDEA has a higher H₂S selectivity than 2-AMP.

In the case of natural gas treatment for pipeline gas too, selective removal of H₂S over CO₂ may be desirable. The absorption step in natural gas treatment is typically effected at high pressures of about 20 to 130 bar (absolute). In general, distinctly higher partial acid gas pressures are present compared, for example, to tail gas treatment or coal gasification, namely, for example, at least 0.2 bar for H₂S and at least 1 bar for CO₂.

A use example within this pressure range is disclosed in U.S. Pat. No. 4,101,633, in which a process for removing carbon dioxide from gas mixtures is described. An absorbent comprising at least 50% of a sterically hindered alkanolamine and at least 10% of a tertiary amino alcohol is used. U.S. Pat. No. 4,094,957 discloses a use example within this pressure range, in which a process for removing carbon dioxide from a gas mixture is described.

An absorbent comprising a basic alkali metal salt or hydroxide, at least one sterically hindered amine and a C₄₋₈ amino acid is used.

In many cases, the aim in natural gas treatment is, simultaneous removal of H₂S and CO₂, wherein given H₂S limits have to be observed but complete removal of CO₂ is unnecessary. The specification typical of pipeline gas requires acid gas removal to about 1.5% to 3.5% by volume of CO₂ and less than 4 ppmv of H₂S. In these cases, maximum H₂S selectivity is undesirable.

US 2013/0243676 describes a process for absorption of H₂S and CO₂ from a gas mixture with an absorbent comprising a highly sterically hindered tertiary etheramine triethylene glycol alcohol or derivatives thereof and a liquid amine.

It is an object of the invention to specify an absorbent and a process for the removal of hydrogen sulfide and carbon dioxide, wherein the regeneration energy of the absorbent is at a minimum.

The object is achieved by an absorbent for selective removal of hydrogen sulfide from a fluid stream, comprising an aqueous solution comprising:

-   a) a tertiary amine of the general formula (I)

-   -   in which R₁ is a C₂₋₄-hydroxyalkyl and R₂ and R₃ are each         independently selected from C₁₋₃-alkyl and C₂₋₄-hydroxyalkyl;

-   b) an aminic pH promoter, the aminic pH promoter being selected from     compounds of the general formula (II)

-   -   in which R₄ is selected from hydrogen; OR₇ in which R₇ is         selected from hydrogen and C₁₋₄-alkyl; and NR₈R₉ in which R₈ and         R₉ are each independently selected from C₁₋₅-alkyl and         C₂₋₅-hydroxyalkyl or R₈ is hydrogen and R₉ is selected from         C₁₋₅-alkyl and C₂₋₅-hydroxyalkyl; R₅ and Re are each         independently selected from C₁₋₅-alkyl and C₂₋₆-hydroxyalkyl or         R₅ is hydrogen and Re is selected from C₁₋₅-alkyl and         C₂₋₅-hydroxyalkyl;     -   of the general formula (III)

-   -   in which R₁₀, R₁₁, R₁₂ and R₁₃ are each independently selected         from C₁₋₅-alkyl, C₁₋₅-aminoalkyl, C₂₋₅-hydroxyalkyl and         (di-C₁₋₄-alkylamino)-C₁₋₅-alkyl; and x is an Integer from 2 to         4;     -   of the general formula (IV)

-   -   in which R₁₄ and R₁₅ are each independently selected from         hydrogen, C₁₋₄-alkyl and C₁₋₄-hydroxyalkyl, with the proviso         that the R₁₄ and R₁₅ radicals on the carbon atom bonded directly         to the nitrogen atom are C₁₋₄-alkyl or C₁₋₄-hydroxyalkyl; and x         is an integer from 2 to 4;     -   and of the general formula (V)

-   -   in which R₁₆, R₁₇ and R₁₈ are each independently selected from         C₁₋₅-alkyl, C₁₋₅-aminoalkyl, C₂₋₅-hydroxyalkyl and         (di-C₁₋₄-alkylamino)-C₁₋₅-alkyl;

-   c) an acid having a pK_(A) of less than 6 in such an amount that the     pH of the aqueous solution measured at 120° C. is 7.9 to less than     8.8.

Protonation equilibria form between the acid and the amines according to a) and/or b). The position of the equilibria is temperature-dependent, and the equilibrium is shifted at higher temperatures toward the free oxonium ion and/or the amine salt having the lower enthalpy of protonation. Amines according to b) exhibit a particularly marked temperature dependence of the protonation equilibrium. The result of this is that, at relatively lower temperatures as exist in the absorption step, the higher pH promotes efficient acid gas absorption, whereas, at relatively higher temperatures as exist in the desorption step, the lower pH supports the release of the absorbed acid gases.

A measure that may be used for the temperature dependence of the protonation equilibrium is the difference ΔpK_(A) (120-50° C.) between the pK_(A) of the pH promoter measured at 120° C. and the pK_(A) of the pH promoter measured at 50° C. It is expected that a high difference in the ΔpK_(A) values of the pH promoter b) between the absorption and desorption temperature together with the adjustment of the pH according to c) will cause a lower regeneration energy.

In general, the total concentration of a) and b) in the aqueous solution is 10% to 60% by weight, preferably 20% to 50% by weight, more preferably 30% to 50% by weight.

The molar ratio of b) to a) is in the range from 0.05 to 1.0, preferably 0.1 to 0.9.

The aqueous solution comprises an acid c) having a pK_(A) of less than 6 in such an amount that the pH of the aqueous solution measured at 120° C. is 7.9 to less than 8.8, preferably 8.0 to less than 8.8, more preferably 8.0 to less than 8.5, most preferably 8.0 to less than 8.2.

It has been found that the absorbent is subject to stability limits within the above-defined limits of the composition. Higher amounts of acid than specified or a greater molar ratio of b) to a) lead to a deterioration in stability and accelerated breakdown of the absorbent at elevated temperature.

The inventive absorbent comprises, as component a), at least one tertiary amine of the formula (I)

in which R₁ is a C₂₋₄-hydroxyalkyl and R₂ and R₃ are each independently selected from C₁₋₃-alkyl and C₂₋₄-hydroxyalkyl. A “tertiary amine” is understood to mean compounds having at least one tertiary amino group. The tertiary amine preferably comprises exclusively tertiary amino groups, meaning that it does not comprise any primary or secondary amino groups alongside at least one tertiary amino group. The tertiary amine is preferably a monoamine. The tertiary amine preferably does not have any acidic groups such as, in particular, phosphonic acid, sulfonic acid and/or carboxylic acid groups.

Suitable amines a) include especially tertiary alkanolamines such as bis(2-hydroxyethyl)methylamine (methyldiethanolamine, MDEA), tris(2-hydroxyethyl)amine (triethanolamine, TEA), tributanolamine, 2-diethylaminoethanol (diethylethanolamine, DEEA), 2-dimethylaminoethanol (dimethylethanolamine, DMEA), 3-dimethylamino-1-propanol (N,N-dimethylpropanolamine), 3-diethylamino-1-propanol, 2-diisopropylaminoethanol (DIEA), N,N-bis(2-hydroxypropyl)methylamine (methyldiisopropanolamine, MDIPA); and mixtures thereof.

Particular preference is given to methyldiethanolamine (MDEA).

The aminic pH promoter b) is selected from compounds of the general formula (II)

in which R₄ is selected from hydrogen; OR₇ in which R₇ is selected from hydrogen and C₁₋₄-alkyl; and NR₈R₉ in which R₈ and R₉ are each independently selected from C₁₋₅-alkyl and C₂₋₅-hydroxyalkyl or R₈ is hydrogen and R₉ is selected from C₁₋₅-alkyl and C₂₋₅-hydroxyalkyl; R₅ and R₆ are each independently selected from C₁₋₅-alkyl and C₂₋₅-hydroxyalkyl or R₅ is hydrogen and R₆ is selected from C₁₋₅-alkyl and C₂₋₅-hydroxyalkyl.

Compounds of the general formula (II) are, for example, cyclohexyl-N,N-dimethylamine and 1,4-bis(dimethylamino)cyclohexane;

of the general formula (III)

In which R₁₀, R₁₁, R₁₂ and R₁₃ are each independently selected from C₁₋₅-alkyl, C₁₋₅-aminoalkyl, C₂₋₅-hydroxyalkyl and (di-C₁₋₄-alkylamino)-C₁₋₅-alkyl; and x is an integer from 2 to 4.

A compound of the general formula (III) is, for example, hydroxyethylbis(dimethylaminopropyl)amine;

of the general formula (IV)

in which R₁₄ and R₁₅ are each independently selected from hydrogen, C₁₋₄-alkyl and C₁₋₄-hydroxyalkyl, with the proviso that the R₁₄ and R₁₅ radicals on the carbon atom bonded directly to the nitrogen atom are C₁₋₄-alkyl or C₁₋₄-hydroxyalkyl; and x is an integer from 2 to 4.

A compound of the general formula (IV) is, for example, 2-amino-2-methylpropanol (2-AMP);

and of the general formula (V)

in which R₁₈, R₁₇ and R₁₈ are each independently selected from C₁₋₅-alkyl, C₁₋₅-aminoalkyl, C₂₋₅-hydroxyalkyl and (di-C₁₋₄-alkylamino)-C₁₋₅-alkyl.

A compound of the general formula (V) is, for example, N,N,N′,N′,N″,N″-hexamethyl-1,3,5-triazine-1,3,5(2H,4H,6H)-tripropanamine.

Preferably, the pH promoter b) Is selected from compounds of the general formula (II), compounds of the general formula (III) and compounds of the general formula (V), more preferably from compounds of the general formula (II) and compounds of the general formula (III). Most preferably, the pH promoter b) is selected from compounds of the formula (II), especially from compounds having exclusively tertiary amino groups, for example cyclohexyl-N,N-dimethylamine and 1,4-bis(dimethylamino)cyclohexane. Most preferred is cyclohexyl-N,N-dimethylamine.

The difference ΔpK_(A) (120-50° C.) between the pK_(A) of the pH promoter measured at 120° C. and the pK_(A) of the pH promoter measured at 50° C. is preferably at least 1.50. In the case of amines having more than one dissociation stage, this condition is considered to be met when at least one dissociation stage has this value for ΔpK_(A) (120-50° C.).

The pK_(A) values are suitably determined in aqueous solution with an amine concentration of 0.01 mol/kg at the given temperature by determining the pH at the point of half-equivalence of the dissociation stage under consideration by means of addition of hydrochloric acid (1st dissociation stage 0.005 mol/kg; 2nd dissociation stage: 0.015 mol/kg; 3rd dissociation stage: 0.025 mol/kg). Measurement is accomplished using a thermostated closed jacketed vessel in which the liquid was blanketed with nitrogen. The Hamilton Polylite Plus 120 pH electrode was used, which was calibrated with pH 7 and pH 12 buffer solutions.

The value of ΔpK_(A) (120-50° C.) depends on the structure of the aminic pH promoter. Steric hindrance of at least one amino group and/or the presence of two or more nitrogen atoms per molecule of the pH promoter favor high values of ΔpK_(A) (120-50° C.).

A sterically hindered primary amino group is understood to mean the presence of at least one tertiary carbon atom directly adjacent to the nitrogen atom of the amino group. A sterically hindered secondary amino group is understood to mean the presence of at least one secondary or tertiary carbon atom directly adjacent to the nitrogen atom of the amino group. The aminic pH promoters of b) also comprise compounds which are referred to in the prior art as highly sterically hindered amines and have a steric parameter (Taft constant) E_(s) of more than 1.75.

A secondary carbon atom is understood to mean a carbon atom which, apart from the bond to the sterically hindered position, has two carbon-carbon bonds. A tertiary carbon atom is understood to mean a carbon atom which, apart from the bond to the sterically hindered position, has three carbon-carbon bonds.

The table below gives the pK_(A) values of illustrative amines at 50° C. and 120° C., and the respective difference ΔpK_(A) (120-50° C.).

Dissociation pK_(A) pK_(A) ΔpK_(A) Amine stage (50° C.) (120° C.) (120 − 50° C.) Cyclohexyl-N,N-dimethylamine pK_(A1) 10.01 8.00 1.99 1,4-Bis(dimethylamino)cyclohexane pK_(A1) 9.80 8.17 1.63 pK_(A2) 8.01 6.67 1.34 Hydroxyethylbis- pK_(A1) 10.14 8.63 1.51 (dimethylaminopropyl)amine pK_(A2) 10.13 8.62 1.51 pK_(A3) 10.12 8.69 1.43 N,N,N′,N′,N″,N″-Hexamethyl-1,3,5- pK_(A1) 11.37 9.78 1.59 triazine-1,3,5(2H,4H,6H)- pK_(A2) 11.23 9.35 1.88 tripropanamine** pK_(A3) 10.45 7.97 2.48 Methyldiethanolamine (MDEA)* pK_(A1) 8.12 6.94 1.18 *comparative compound **only the first three dissociation stages determined

The inventive absorbent comprises at least one acid having a pK_(A) at 20° C. of less than 6, especially less than 5. In the case of acids having more than one dissociation stage and accordingly more than one pK_(A), this requirement is met when one of the pK_(A) values is within the range specified. The acid is suitably selected from protic acids (Brønsted acids).

The acid is selected from organic and inorganic acids. Suitable organic acids comprise, for example, phosphonic acids, sulfonic acids, carboxylic acids and amino acids. In particular embodiments, the acid is a polybasic acid.

Suitable acids are, for example,

mineral acids such as hydrochloric acid, sulfuric acid, amidosulfuric acid, phosphoric acid, partial esters of phosphoric acid, for example mono- and dialkyl phosphates and mono- and diaryl phosphates such as tridecyl phosphate, dibutyl phosphate, diphenyl phosphate and bis(2-ethylhexyl) phosphate; boric acid; carboxylic acids, for example saturated aliphatic monocarboxylic acids such as formic acid, acetic acid, propionic acid, butyric acid, isobutyric acid, valeric acid, isovaleric acid, pivalic acid, caproic acid, n-heptanoic acid, caprylic acid, 2-ethylhexanoic acid, pelargonic acid, neodecanoic acid, undecanoic acid, lauric acid, tridecanoic acid, myristic acid, pentadecanoic acid, palmitic acid, margaric acid, stearic acid, isostearic acid, arachic acid, behenic acid; saturated aliphatic polycarboxylic acids such as oxalic acid, malonic acid, succinic acid, glutaric acid, adipic acid, pimelic acid, suberic acid, azelaic acid, sebacic acid, dodecanedioic acid; cycloaliphatic mono- and polycarboxylic acids such as cyclohexanecarboxylic acid, hexahydrophthalic acid, tetrahydrophthalic acid, resin acids, naphthenic acids; aliphatic hydroxycarboxylic acids such as glycolic acid, lactic acid, mandelic acid, hydroxybutyric acid, tartaric acid, malic acid, citric acid; halogenated aliphatic carboxylic acids such as trichloroacetic acid or 2-chloropropionic acid; aromatic mono- and polycarboxylic acids such as benzoic acid, salicylic acid, gallic acid, the positionally isomeric toluic acids, methoxybenzoic acids, chlorobenzoic acids, nitrobenzoic acids, phthalic acid, terephthalic acid, isophthalic acid; technical carboxylic acid mixtures, for example Versatic acids; sulfonic acids such as methylsulfonic acid, butylsulfonic acid, 3-hydroxypropylsulfonic acid, sulfoacetic acid, benzenesulfonic acid, p-toluenesulfonic acid, p-xylenesulfonic acid, 4-dodecylbenzenesulfonic acid, 1-naphthalenesulfonic acid, dinonylnaphthalenesulfonic acid and dinonylnaphthalenedisulfonic acid, trifluoromethyl- or nonafluoron-butylsulfonic acid, camphorsulfonic acid, 2-(4-(2-hydroxyethyl)-1-piperazinyl)ethanesulfonic acid (HEPES); organic phosphonic acids, for example phosphonic acids of the formula (VI) R₁₀—PO₃H  (VI) in which R₁₉ is C₁₋₁₈-alkyl optionally substituted by up to four substituents independently selected from carboxyl, carboxamido, hydroxyl and amino.

These include alkylphosphonic acids such as methylphosphonic acid, propylphosphonic acid, 2-methylpropylphosphonic acid, t-butylphosphonic acid, n-butylphosphonic acid, 2,3-dimethylbutylphosphonic acid, octylphosphonic acid; hydroxyalkylphosphonic acids such as hydroxymethylphosphonic acid, 1-hydroxyethylphosphonic acid, 2-hydroxyethylphosphonic acid; arylphosphonic acids such as phenylphosphonic acid, tolylphosphonic acid, xylylphosphonic acid, aminoalkylphosphonic acids such as aminomethylphosphonic acid, 1-aminoethylphosphonic acid, 1-dimethylaminoethylphosphonic acid, 2-aminoethylphosphonic acid, 2-(N-methylamino)ethylphosphonic acid, 3-aminopropylphosphonic acid, 2-aminopropylphosphonic acid, 1-aminopropylphosphonic acid, 1-aminopropyl-2-chloropropylphosphonic acid, 2-aminobutylphosphonic acid, 3-aminobutylphosphonic acid, 1-aminobutylphosphonic acid, 4-aminobutylphosphonic acid, 2-aminopentylphosphonic acid, 5-aminopentylphosphonic acid, 2-aminohexylphosphonic acid, 5-aminohexylphosphonic acid, 2-aminooctylphosphonic acid, 1-aminooctylphosphonic acid, 1-aminobutylphosphonic acid; amidoalkylphosphonic acids such as 3-hydroxymethylamino-3-oxopropylphosphonic acid; and phosphonocarboxylic acids such as 2-hydroxyphosphonoacetic acid and 2-phosphonobutane-1,2,4-tricarboxylic acid;

phosphonic acids of the formula (VII)

in which R₂₀ is H or C₁₋₆-alkyl, Q is H, OH or NY₂ and Y is H or CH₂PO₃H₂, such as 1-hydroxyethane-1,1-diphosphonic acid; phosphonic acids of the formula (VIII)

in which Z is C₂₋₆-alkylene, cycloalkanediyl, phenylene, or C₂₋₆-alkylene interrupted by cycloalkanediyl or phenylene, Y is CH₂PO₃H₂ and m is 0 to 4, such as ethylenediaminetetra(methylenephosphonic acid), diethylenetriaminepenta(methylenephosphonic acid) and bis(hexamethylene)triaminepenta(methylenephosphonic acid); phosphonic acids of the formula (IX) R₂₁—NY₂  (IX) in which R₂₁ is C₁₋₆-alkyl, C₂₋₆-hydroxyalkyl or Y, and Y is CH₂PO₃H₂, such as nitrilotris(methylenephosphonic acid) and 2-hydroxyethyliminobis(methylenephosphonic acid); aminocarboxylic acids having tertiary amino groups or amino groups having at least one secondary or tertiary carbon atom immediately adjacent to the amino group, such as α-amino acids having tertiary amino groups or amino groups having at least one secondary or tertiary carbon atom immediately adjacent to the amino group, such as N,N-dimethylglycine (dimethylaminoacetic acid), N,N-diethylglycine, alanine (2-aminopropionic acid), N-methylalanine (2-(methylamino)propionic acid), N,N-dimethylalanine, N-ethylalanine, 2-methylalanine (2-aminoisobutyric acid), leucine (2-amino-4-methylpentan-1-oic acid), N-methylleucine, N,N-dimethylleucine, isoleucine (1-amino-2-methylpentanoic acid), N-methylisoleucine, N,N-dimethylisoleucine, valine (2-aminoisovaleric acid), α-methylvaline (2-amino-2-methylisovaleric acid), N-methylvaline (2-methylaminoisovaleric acid), N,N-dimethylvaline, proline (pyrrolidine-2-carboxylic acid), N-methylproline, N-methylserine, N,N-dimethylserine, 2-(methylamino)isobutyric acid, piperidine-2-carboxylic acid, N-methylpiperidine-2-carboxylic acid, β-amino acids having tertiary amino groups or amino groups having at least one secondary or tertiary carbon atom immediately adjacent to the amino group, such as 3-dimethylaminopropionic acid, N-methyliminodipropionic acid, N-methylpiperidine-3-carboxylic acid, γ-amino acids having tertiary amino groups or amino groups having at least one secondary or tertiary carbon atom immediately adjacent to the amino group, such as 4-dimethylaminobutyric acid, or aminocarboxylic acids having tertiary amino groups or amino groups having at least one secondary or tertiary carbon atom immediately adjacent to the amino group, such as N-methylpiperidine-4-carboxylic acid.

Among the inorganic acids, preference is given to phosphoric acid and sulfuric acid.

Among the carboxylic acids, preference is given to formic acid, acetic acid, benzoic acid, succinic acid and adipic acid.

Among the sulfonic acids, preference is given to methanesulfonic acid, p-toluenesulfonic acid and 2-(4-(2-hydroxyethyl)-1-piperazinyl)ethanesulfonic acid (HEPES).

Among the phosphonic acids, preference is given to 2-hydroxyphosphonoacetic acid, 2-phosphonobutane-1,2,4-tricarboxylic acid, 1-hydroxyethane-1,1-diphosphonic acid, ethylenediaminetetra(methylenephosphonic acid), diethylenetriaminepenta(methylenephosphonic acid), bis(hexamethylene)triaminepenta(methylenephosphonic acid) (HDTMP) and nitrilotris(methylenephosphonic acid), among which 1-hydroxyethane-1,1-diphosphonic acid is particularly preferred.

Among the aminocarboxylic acids having tertiary amino groups or amino groups having at least one secondary or tertiary carbon atom immediately adjacent to the amino group, preference is given to N,N-dimethylglycine and N-methylalanine.

More preferably, the acid is an inorganic acid.

The absorbent may also comprise additives such as corrosion inhibitors, enzymes, etc. In general, the amount of such additives is in the range from about 0.01% to 3% by weight of the absorbent.

Preferably, the absorbent does not comprise any sterically unhindered primary amine or sterically unhindered secondary amine. Compounds of this kind act as strong activators of CO₂ absorption. As a result, the H₂S selectivity of the absorbent can be lost.

A sterically unhindered primary amine is understood to mean compounds having primary amino groups to which only hydrogen atoms or primary or secondary carbon atoms are bonded. A sterically unhindered secondary amine is understood to mean compounds having secondary amino groups to which only hydrogen atoms or primary carbon atoms are bonded.

The invention also relates to a process for removing acidic gases from a fluid stream, in which the fluid stream is contacted with the absorbent defined above.

In general, the laden absorbent is regenerated by

a) heating,

b) decompression,

c) stripping with an inert fluid

or a combination of two or all of these measures.

The process of the invention is suitable for treatment of all kinds of fluids. Fluids are firstly gases such as natural gas, synthesis gas, coke oven gas, cracking gas, coal gasification gas, cycle gas, landfill gases and combustion gases, and secondly liquids that are essentially immiscible with the absorbent, such as LPG (liquefied petroleum gas) or NGL (natural gas liquids). The process according to the invention is particularly suitable for treatment of hydrocarbonaceous fluid streams. The hydrocarbons present are, for example, aliphatic hydrocarbons such as C₁-C₄ hydrocarbons such as methane, unsaturated hydrocarbons such as ethylene or propylene, or aromatic hydrocarbons such as benzene, toluene or xylene.

The absorbent or process according to the invention is suitable for removal of CO₂ and H₂S. As well as carbon dioxide and hydrogen sulfide, it is possible for other acidic gases to be present in the fluid stream, such as COS and mercaptans. In addition, it is also possible to remove SO₃, SO₂, CS₂ and HCN.

The process according to the invention is suitable for selective removal of hydrogen sulfide over CO₂. In the present context, “selectivity for hydrogen sulfide” is understood to mean the value of the following quotient:

$\frac{\frac{{y\left( {H_{2}S} \right)}_{feed} - {y\left( {H_{2}S} \right)}_{treat}}{{y\left( {H_{2}S} \right)}_{feed}}}{\frac{{y\left( {CO}_{2} \right)}_{feed} - {y\left( {CO}_{2} \right)}_{treat}}{{y\left( {CO}_{2} \right)}_{feed}}}$ in which y(H₂S)_(feed) is the molar proportion (mol/mol) of H₂S in the starting fluid, y(H₂S)_(treat) is the molar proportion in the treated fluid, y(CO₂)_(feed) is the molar proportion of CO₂ in the starting fluid and y(CO₂)_(treat) is the molar proportion of CO₂ in the treated fluid. The selectivity for hydrogen sulfide is preferably 1 to 8.

In preferred embodiments, the fluid stream is a fluid stream comprising hydrocarbons, especially a natural gas stream. More preferably, the fluid stream comprises more than 1.0% by volume of hydrocarbons, even more preferably more than 5.0% by volume of hydrocarbons, most preferably more than 15% by volume of hydrocarbons.

The partial hydrogen sulfide pressure in the fluid stream is typically at least 2.5 mbar. In preferred embodiments, a partial hydrogen sulfide pressure of at least 0.1 bar, especially at least 1 bar, and a partial carbon dioxide pressure of at least 0.2 bar, especially at least 1 bar, is present in the fluid stream. The partial pressures stated are based on the fluid stream on first contact with the absorbent in the absorption step.

In preferred embodiments, a total pressure of at least 3.0 bar, more preferably at least 5.0 bar, even more preferably at least 20 bar, is present in the fluid stream. In preferred embodiments, a total pressure of at most 180 bar is present in the fluid stream. The total pressure is based on the fluid stream on first contact with the absorbent in the absorption step.

In the process according to the invention, the fluid stream is contacted with the absorbent in an absorption step in an absorber, as a result of which carbon dioxide and hydrogen sulfide are at least partly scrubbed out. This gives a CO₂- and H₂S-depleted fluid stream and a CO₂- and H₂S-laden absorbent.

The absorber used is a scrubbing apparatus used in customary gas scrubbing processes. Suitable scrubbing apparatuses are, for example, columns having random packings, having structured packings and having trays, membrane contactors, radial flow scrubbers, jet scrubbers, Venturi scrubbers and rotary spray scrubbers, preferably columns having structured packings, having random packings and having trays, more preferably columns having trays and having random packings. The fluid stream is preferably treated with the absorbent in a column in countercurrent. The fluid is generally fed into the lower region and the absorbent into the upper region of the column. Installed in tray columns are sieve trays, bubble-cap trays or valve trays, over which the liquid flows. Columns having random packings can be filled with different shaped bodies. Heat and mass transfer are improved by the increase in the surface area caused by the shaped bodies, which are usually about 25 to 80 mm in size. Known examples are the Raschig ring (a hollow cylinder), Pall ring, Hiflow ring, Intalox saddle and the like. The random packings can be introduced into the column in an ordered manner, or else randomly (as a bed). Possible materials include glass, ceramic, metal and plastics. Structured packings are a further development of ordered random packings. They have a regular structure. As a result, it is possible in the case of structured packings to reduce pressure drops in the gas flow. There are various designs of structured packings, for example woven packings or sheet metal packings. Materials used may be metal, plastic, glass and ceramic.

The temperature of the absorbent in the absorption step is generally about 30 to 100° C., and when a column is used is, for example, 30 to 70° C. at the top of the column and 50 to 100° C. at the bottom of the column.

The process according to the invention may comprise one or more, especially two, successive absorption steps. The absorption can be conducted in a plurality of successive component steps, in which case the crude gas comprising the acidic gas constituents is contacted with a substream of the absorbent in each of the component steps. The absorbent with which the crude gas is contacted may already be partly laden with acidic gases, meaning that it may, for example, be an absorbent which has been recycled from a downstream absorption step into the first absorption step, or be partly regenerated absorbent. With regard to the performance of the two-stage absorption, reference is made to publications EP 0 159 495, EP 0 190 434, EP 0 359 991 and WO 00100271.

The person skilled in the art can achieve a high level of hydrogen sulfide removal with a defined selectivity by varying the conditions in the absorption step, such as, more particularly, the absorbent/fluid stream ratio, the column height of the absorber, the type of contact-promoting internals in the absorber, such as random packings, trays or structured packings, and/or the residual loading of the regenerated absorbent.

A low absorbent/fluid stream ratio leads to an elevated selectivity; a higher absorbent/fluid stream ratio leads to a less selective absorption. Since CO₂ is absorbed more slowly than H₂S, more CO₂ is absorbed in a longer residence time than in a shorter residence time. A higher column therefore brings about a less selective absorption.

Trays or structured packings with relatively high liquid holdup likewise lead to a less selective absorption. The heating energy introduced in the regeneration can be used to adjust the residual loading of the regenerated absorbent. A lower residual loading of regenerated absorbent leads to improved absorption.

The process preferably comprises a regeneration step in which the CO₂- and H₂S-laden absorbent is regenerated. In the regeneration step, CO₂ and H₂S and optionally further acidic gas constituents are released from the CO₂- and H₂S-laden absorbent to obtain a regenerated absorbent. Preferably, the regenerated absorbent is subsequently recycled into the absorption step. In general, the regeneration step comprises at least one of the measures of heating, decompressing and stripping with an inert fluid.

The regeneration step preferably comprises heating of the absorbent laden with the acidic gas constituents, for example by means of a boiler, natural circulation evaporator, forced circulation evaporator or forced circulation flash evaporator. The absorbed acid gases are stripped out by means of the steam obtained by heating the solution. Rather than steam, it is also possible to use an inert fluid such as nitrogen. The absolute pressure in the desorber is normally 0.1 to 3.5 bar, preferably 1.0 to 2.5 bar. The temperature is normally 50° C. to 170° C., preferably 80° C. to 130° C., the temperature of course being dependent on the pressure.

The regeneration step may alternatively or additionally comprise a decompression. This includes at least one decompression of the laden absorbent from a high pressure as exists in the conduction of the absorption step to a lower pressure. The decompression can be accomplished, for example, by means of a throttle valve and/or a decompression turbine. Regeneration with a decompression stage is described, for example, in publications U.S. Pat. Nos. 4,537,753 and 4,553,984.

The acidic gas constituents can be released in the regeneration step, for example, in a decompression column, for example a flash vessel installed vertically or horizontally, or a countercurrent column with internals.

The regeneration column may likewise be a column having random packings, having structured packings or having trays. The regeneration column, at the bottom, has a heater, for example a forced circulation evaporator with circulation pump. At the top, the regeneration column has an outlet for the acid gases released. Entrained absorption medium vapors are condensed in a condenser and recirculated to the column.

It is possible to connect a plurality of decompression columns in series, in which regeneration is effected at different pressures. For example, regeneration can be effected in a preliminary decompression column at a high pressure typically about 1.5 bar above the partial pressure of the acidic gas constituents in the absorption step, and in a main decompression column at a low pressure, for example 1 to 2 bar absolute. Regeneration with two or more decompression stages is described in publications U.S. Pat. Nos. 4,537,753, 4,553,984, EP 0 159 495, EP 0 202 600, EP 0 190 434 and EP 0 121 109.

Because of the optimal matching of the content of the amine components and of the acid, the inventive absorbent has a high loading capacity with acidic gases, which can also be desorbed again easily. In this way, it is possible to significantly reduce energy consumption and solvent circulation in the process according to the invention.

For a minimum energy requirement in the regeneration of the absorbent, it is advantageous when there is a maximum difference between the pH at the temperature of the absorption and the pH at the temperature of the desorption, since this facilitates the separation of the acid gases from the absorbent.

The invention Is illustrated in detail by the appended drawing and the examples which follow.

FIG. 1 is a schematic diagram of a plant suitable for performing the process according to the invention.

According to FIG. 1, via the inlet Z, a suitably pretreated gas comprising hydrogen sulfide and carbon dioxide is contacted in countercurrent, in an absorber A1, with regenerated absorbent which is fed in via the absorbent line 1.01. The absorbent removes hydrogen sulfide and carbon dioxide from the gas by absorption; this affords a hydrogen sulfide- and carbon dioxide-depleted clean gas via the offgas line 1.02.

Via the absorbent line 1.03, the heat exchanger 1.04 in which the CO₂- and H₂S-laden absorbent is heated up with the heat from the regenerated absorbent conducted through the absorbent line 1.05, and the absorbent line 1.06, the CO₂- and H₂S-laden absorbent is fed to the desorption column D and regenerated.

Between the absorber A1 and heat exchanger 1.04, a flash vessel may be provided (not shown in FIG. 1), in which the CO₂- and H₂S-laden absorbent is decompressed to, for example, 3 to 15 bar.

From the lower part of the desorption column D, the absorbent is conducted into the boiler 1.07, where it is heated. The mainly water-containing vapor is recycled into the desorption column D, while the regenerated absorbent is fed back to the absorber A1 via the absorbent line 1.05, the heat exchanger 1.04 in which the regenerated absorbent heats up the CO₂- and H₂S-laden absorbent and at the same time cools down itself, the absorbent line 1.08, the cooler 1.09 and the absorbent line 1.01. Instead of the boiler shown, it is also possible to use other heat exchanger types to generate the stripping vapor, such as a natural circulation evaporator, forced circulation evaporator or forced circulation flash evaporator. In the case of these evaporator types, a mixed-phase stream of regenerated absorbent and stripping vapor is returned to the bottom of the desorption column D, where the phase separation between the vapor and the absorbent takes place. The regenerated absorbent to the heat exchanger 1.04 is either drawn off from the circulation stream from the bottom of the desorption column D to the evaporator or conducted via a separate line directly from the bottom of the desorption column D to the heat exchanger 1.04.

The CO₂- and H₂S-containing gas released in the desorption column D leaves the desorption column D via the offgas line 1.10. It is conducted into a condenser with integrated phase separation 1.11, where it is separated from entrained absorbent vapor. In this and all the other plants suitable for performance of the process according to the invention, condensation and phase separation may also be present separately from one another. Subsequently, a liquid consisting mainly of water is conducted through the absorbent line 1.12 into the upper region of the desorption column D, and a CO₂- and H₂S-containing gas is discharged via the gas line 1.13.

EXAMPLES

In the examples, the following abbreviations are used:

-   MDEA: methyldiethanolamine -   HMTATPA:     N,N,N′,N′,N″,N″-hexamethyl-1,3,5-triazine-1,3,5(2H,4H,6H)tripropanamine -   TBAEE: 2-(2-(tert-butylamino)ethoxy)ethanol

REFERENCE EXAMPLE

In this example, the correlation between the value of pH(50° C.)-pH(120° C.) and the regeneration energy required for various absorbents was examined.

The temperature dependence of the pH of aqueous amine solutions or partly neutralized amine solutions within the temperature range from 50° C. to 120° C. was determined.

The Hamilton Polylite Plus 120 pH electrode was used, which is calibrated with pH 7 and pH 12 buffer solutions. A pressure apparatus with nitrogen blanketing was used, in which the pH can be measured up to 120° C.

The table which follows reports the pH (50° C.), the pH (120° C.) and the difference pH(50° C.)-pH(120° C.) for illustrative aqueous compositions.

pH pH pH (50° C.) − Ex. Aqueous composition b/a* (50° C.) (120° C.) pH (120° C.) R1-1 40% MDEA — 11.01 9.58 1.43 R1-2 40% MDEA + 0.5% H₃PO₄ — 9.76 8.29 1.47 R-1-3 30% MDEA + 15% TBAEE 0.37 11.19 9.30 1.89 R1-4 30% MDEA + 15% TBAEE + 0.8% H₃PO₄ 0.37 10.21 8.49 1.72 R1-5 30% MDEA + 15% TBAEE + 1.6% H₃PO₄ 0.37 9.82 8.06 1.76 R1-6 30% MDEA + 15% TBAEE + 0.6% H₂SO₄ 0.37 10.21 8.40 1.81 R1-7 30% MDEA + 15% TBAEE + 0.8% H₂SO₄ 0.37 9.89 8.16 1.73 R1-8 30% MDEA + 15% TBAEE + 1.2% H₂SO₄ 0.37 9.79 8.13 1.66 R1-9 30% MDEA + 15% TBAEE + 1.6% H₂SO₄ 0.37 9.77 7.90 1.87 R1-10 35% MDEA + 10% 4-hydroxy-2,2,6,6-tetramethylpiperidine + 0.9% H₂SO₄ 0.22 9.87 8.21 1.66 R1-11 35% MDEA + 10% 4-hydroxy-2,2,6,6-tetramethylpiperidine + 1.2% H₂SO₄ 0.22 9.68 8.03 1.65 *molar ratio of b/a

It is clear that there is a greater difference between the pH values at 50° C. and 120° C. in the examples in which the aqueous composition comprises a further amine in addition to MDEA and an acid.

In a pilot plant, the heating energy introduced in the course of regeneration for a defined H₂S concentration of the cleaned gas was examined for aqueous absorbents.

The pilot plant corresponded to FIG. 1. In the absorber, a structured packing was used. The pressure was 60 bar. The packing height in the absorber was 3.2 m with a column diameter of 0.0531 m. In the desorber, a structured packing was used. The pressure was 1.8 bar. The packing height in the desorber was 6.0 m with a diameter of 0.085 m.

A gas mixture of 93% by volume of N₂, 5% by volume of CO₂ and 2% by volume of H₂S was conducted into the absorber at a mass flow rate of 47 kg/h and a temperature of 40° C. In the absorber, the absorbent circulation rate was 60 kg/h. The temperature of the absorbent was 50° C. The regeneration energy was adjusted such that an H₂S concentration of 5 ppm was attained in the cleaned gas.

The following table shows the results of these experiments:

Relative regeneration Ex. Aqueous composition energy* [%] R2-1 40% MDEA 100.0 R2-2 40% MDEA + 0.5% H₃PO₄ 73.3 R2-3 30% MDEA + 15% TBAEE 91.6 R2-4 30% MDEA + 15% TBAEE + 0.8% H₃PO₄ 57.8 R2-5 30% MDEA + 15% TBAEE + 1.6% H₃PO₄ 56.9 R2-6 30% MDEA + 15% TBAEE + 0.6% H₂SO₄ 65.1 R2-7 30% MDEA + 15% TBAEE + 0.8% H₂SO₄ 64.8 R2-8 30% MDEA + 15% TBAEE + 1.2% H₂SO₄ 64.1 R2-9 30% MDEA + 15% TBAEE + 1.6% H₂SO₄ 62.2 R2-10 35% MDEA + 10% 4-hydroxy-2,2,6,6- 70.5 tetramethylpiperidine + 0.9% H₂SO₄ R2-11 35% MDEA + 10% 4-hydroxy-2,2,6,6- 64.6 tetramethylpiperidine + 1.2% H₂SO₄ *relative to example 2-1*

It is clear that a greater difference pH(50° C.)-pH(120° C.) in the case of compositions having comparable pH values at 120° C. results in a lower regeneration energy.

Example 1

The temperature dependence of the pH of aqueous amine solutions or partly neutralized amine solutions within the temperature range from 50° C. to 120° C. was determined as in the reference example.

The table which follows reports the pH (50° C.), the pH (120° C.) and the difference pH(50° C.)-pH(120° C.).

pH pH pH (50° C.) − Ex. Aqueous composition b/a ** (50° C.) (120° C.) pH (120° C.) 1-1 35% MDEA + 10% cyclohexyl-N,N-dimethyl- 0.27 9.62 8.05 1.57 amine + 1.0% H₂SO₄ 1-2 30% MDEA + 15% bis(dimethylamino)cyclo- 0.35 9.83 8.14 1.69 hexane + 2.0% H₂SO₄ 1-3 40% MDEA + 12% HMTATPA + 5.15% H₂SO₄ 0.10 9.92 8.09 1.83 1-4 40% MDEA + 12% HMTATPA + 6.0% H₂SO₄ 0.10 9.71 7.90 1.81 1-5 40% MDEA + 8.5% hydroxyethylbis(dimethyl- 0.11 9.52 7.90 1.62 aminopropyl)amine + 2.0% H₂SO₄

It is clear that the inventive absorbents have a relatively high difference pH(50° C.)-pH(120° C.). With regard to the results of the reference example, this serves as an indication of a low regeneration energy required. 

The invention claimed is:
 1. An absorbent for selective removal of hydrogen sulfide over carbon dioxide from a fluid stream, the absorbent comprising an aqueous solution comprising: a) a tertiary amine of the general formula (I)

in which R₁ is a C₂₋₄-hydroxyalkyl and R₂ and R₃ are each independently selected from C₁₋₃-alkyl and C₂₋₄-hydroxyalkyl; b) an aminic pH promoter, the aminic pH promoter being selected from the group consisting of: compounds of the general formula (II):

in which R₄ is selected from the group consisting of hydrogen; OR₇ in which R₇ is selected from the group consisting of hydrogen and C₁₋₄-alkyl; and NR₈R₉ in which R₈ and R₉ are each independently selected from the group consisting of C₁₋₅-alkyl and C₂₋₅-hydroxyalkyl or R₈ is hydrogen and R₉ is selected from the group consisting of C₁₋₅-alkyl and C₂₋₅-hydroxyalkyl; R₅ and R₆ are each independently selected from the group consisting of C₁₋₅-alkyl and C₂₋₅-hydroxyalkyl or R₅ is hydrogen and R₆ is selected from the group consisting of C₁₋₅-alkyl and C₂₋₅-hydroxyalkyl; and compounds of the general formula (III):

in which R₁₀, R₁₁, R₁₂ and R₁₃ are each independently selected from the group consisting of C₁₋₅-alkyl, C₁₋₅-aminoalkyl, C₂₋₅-hydroxyalkyl and (di-C₁₋₄-alkylamino)-C₁₋₅-alkyl; and x is an integer from 2 to 4; and c) an acid having a pK_(A) of less than 6 in such an amount that a pH of the aqueous solution measured at 120° C. is 7.9 to less than 8.8, wherein a molar ratio of b) to a) is in the range from 0.05 to
 1. 2. The absorbent according to claim 1, wherein the total concentration of a) and b) in the aqueous solution is 10% to 60% by weight.
 3. The absorbent according to claim 1, wherein the tertiary amine a) is methyldiethanolamine.
 4. The absorbent according to claim 1, wherein the molar ratio of b) to a) ranges from 0.1 to 0.9.
 5. The absorbent according to claim 1, wherein the acid is an acid having a pK_(A) of less than
 5. 6. The absorbent according to claim 1, wherein the acid is an inorganic acid.
 7. A process for selectively removing hydrogen sulfide over carbon dioxide from a fluid stream, the process comprising contacting the fluid stream with the absorbent according to claim
 1. 8. The process according to claim 7, wherein the fluid stream comprises hydrocarbons.
 9. The process according to claim 7, wherein there is a partial hydrogen sulfide pressure of at least 0.1 bar and a partial carbon dioxide pressure of at least 0.2 bar in the fluid stream.
 10. The process according to claim 7, wherein the fluid stream has a total pressure of at least 3.0 bar.
 11. The process according to claim 7, further comprising regenerating laden absorbent by a) heating, b) decompression, c) stripping with an inert fluid, or a combination of two or all of these measures. 